Elastometry of Complex Fluid Pendant Capsules

Oil/water interfaces are ubiquitous in nature. Opposing polarities at these interfaces attract surface-active molecules, which can seed complex viscoelastic or even solid interfacial structure. Biorelevant proteins such as hydrophobin, polymers such as PNIPAM, and the asphaltenes in crude oil (CRO) are examples of some systems where such layers can occur. When a pendant drop of CRO is aged in brine, it can form an interfacial elastic membrane of asphaltenes so stiff that it wrinkles and crumples upon retraction. Most of the work studying CRO/brine interfaces focuses on the viscoelastic liquid regime, leaving a wide range of fully solidified, elastic interfaces largely unexplored. In this work, we quantitatively measure elasticity in all phases of drop retraction. In early retraction, the interface shows a fluid viscoelasticity measurable using a Gibbs isotherm or dilatational rheology. Further retraction causes a phase transition to a 2D elastic solid with nonisotropic, nonhomogeneous surface stresses. In this regime, we use new techniques in the elastic membrane theory to fit for the elasticities of these solid capsules. These elastic measurements can help us develop a deeper understanding not only of CRO interfaces but also of the myriad fluid systems with solid interfacial layers.</p

Development and Optimization of Gas-Assisted Gravity Drainage (GAGD) Process for Improved Light Oil Recovery

This is the final report describing the evolution of the project ''Development and Optimization of Gas-Assisted Gravity Drainage (GAGD) Process for Improved Light Oil Recovery'' from its conceptual stage in 2002 to the field implementation of the developed technology in 2006. This comprehensive report includes all the experimental research, models developments, analyses of results, salient conclusions and the technology transfer efforts. As planned in the original proposal, the project has been conducted in three separate and concurrent tasks: Task 1 involved a physical model study of the new GAGD process, Task 2 was aimed at further developing the vanishing interfacial tension (VIT) technique for gas-oil miscibility determination, and Task 3 was directed at determining multiphase gas-oil drainage and displacement characteristics in reservoir rocks at realistic pressures and temperatures. The project started with the task of recruiting well-qualified graduate research assistants. After collecting and reviewing the literature on different aspects of the project such gas injection EOR, gravity drainage, miscibility characterization, and gas-oil displacement characteristics in porous media, research plans were developed for the experimental work to be conducted under each of the three tasks. Based on the literature review and dimensional analysis, preliminary criteria were developed for the design of the partially-scaled physical model. Additionally, the need for a separate transparent model for visual observation and verification of the displacement and drainage behavior under gas-assisted gravity drainage was identified. Various materials and methods (ceramic porous material, Stucco, Portland cement, sintered glass beads) were attempted in order to fabricate a satisfactory visual model. In addition to proving the effectiveness of the GAGD process (through measured oil recoveries in the range of 65 to 87% IOIP), the visual models demonstrated three possible multiphase mechanisms at work, namely, Darcy-type displacement until gas breakthrough, gravity drainage after breakthrough and film-drainage in gas-invaded zones throughout the duration of the process. The partially-scaled physical model was used in a series of experiments to study the effects of wettability, gas-oil miscibility, secondary versus tertiary mode gas injection, and the presence of fractures on GAGD oil recovery. In addition to yielding recoveries of up to 80% IOIP, even in the immiscible gas injection mode, the partially-scaled physical model confirmed the positive influence of fractures and oil-wet characteristics in enhancing oil recoveries over those measured in the homogeneous (unfractured) water-wet models. An interesting observation was that a single logarithmic relationship between the oil recovery and the gravity number was obeyed by the physical model, the high-pressure corefloods and the field data

A Critical Review of Water Chemistry Alteration Technologies to Develop Novel Water Treatment Schemes for SmartWater Flooding in Carbonate Reservoirs

AbstractThe importance of tuning injection water chemistry for upstream is getting beyond formation damage control/water incompatibility to increase oil recovery from waterflooding and different improved oil recovery (IOR)/enhanced oil recovery (EOR) processes. The water chemistry requirements for IOR/EOR have been relatively addressed in the recent literature, but the key challenge for field implementation is to find an easy, practical, and optimum technology to tune water chemistry. The currently available technologies for tuning water chemistry are limited, and most of the existing ones are adopted from the desalination industry, which relies on membrane based separation. Even though these technologies yield a doable solution, they are not the optimum choice to alter injection water chemistry in terms of incorporating selective ions and providing effective water management for large scale applications. In this study, several of the current, emerging, and future desalination technologies are reviewed with an objective to develop potential water treatment solutions that can most efficiently alter injection water chemistry for SmartWater flooding in carbonate reservoirs.Standard chemical precipitation technologies, such as lime/soda ash, alkali, and lime/aluminum based reagent, are only applicable for removing certain ions from seawater. The lime/aluminum based reagent process looks interesting, as it can remove both sulfates and hardness ions to provide some tuning flexibility for key ions included in the SmartWater. There are some new technologies under development that use chemical solvents to extract salt ions from seawater, but their capabilities to selectively remove specific ions need further investigation.Forward osmosis and membrane distillation are the two emerging technologies, and these can provide good alternatives to reverse osmosis seawater desalination for the near-term. These technologies can offer a better cost-effective solution where there is availability of low grade waste heat or steam. The two new desalination technologies, based on dynamic vapor recovery and carrier gas extraction, are well suited to treat high salinity produced water for zero liquid discharge (ZLD). These technologies may not be able to provide an economical solution for seawater desalination. Carbon nanotube desalination, graphene sheet-based desalination, and capacitive deionization are the three potential future seawater desalination technologies identified for the long term. Among these, carbon nanotube based desalination is much attractive, although the technology is still largely under research and development.This review study results show that there is no commercial technology yet available to selectively remove specific ions from seawater in one step and optimally meet desired water chemistry requirements of SmartWater flooding. As a result, different novel schemes involving selected combinations of chemical precipitation, conventional/emerging desalination, and produced water treatment technologies are proposed. These schemes represent both approximate and improved solutions to selectively incorporate specific key ions in the SmartWater, besides presenting the key opportunities to treat produced water/membrane rejects and provide ZLD capabilities in SmartWater flooding applications. The developed novel schemes can provide an attractive solution to capitalize on existing huge produced water resources in Saudi reservoirs to generate SmartWater and minimize wastewater disposal during field-wide implementation.</jats:p

Comparative evaluation of a new MMP determination technique

A new experimental technique of vanishing interfacial tension (VIT) has been reported in recent literature for quick and costeffective determination of gas-oil miscibility. However, this technique has been criticized due to the perceived absence of compositional path specification as well as for lack of the confirmation against standard gas-oil systems. In this paper, we address these concerns by conducting interfacial tension measurements at elevated pressures and temperatures in two standard gas-oil systems and at varying molar compositions of gas and oil in feed mixtures. The two standard gas-oil systems used are: CO2 against n-decane at 100°F, and CO2 against live decane consisting of 25 mole% methane, 30 mole% n-butane and 45 mole% n-decane at 160°F. In addition to the pendent drop technique, the capillary rise technique has been adapted and successfully used for low gas-oil interfacial tension measurements at elevated pressures and temperatures. Though gas-oil ratio was found to have an impact on mass transfer rates, the interfacial tension between gas and oil was unaffected as the fluid phases approached equilibrium. This indicates the compositional path independence of gas-oil interfacial tensions measured at near-equilibrium and miscibilities determined using the VIT technique. The minimum miscibility pressures determined using the VIT technique matched well (within 4-8%) with the reported slim-tube miscibilities for both the standard gas-oil systems used. This paper relates first- and multiple-contact miscibility development in gas injection displacement processes to laboratory gas-oil interfacial tension measurements. We also found that the dynamic behavior of gas-oil interfacial tension reflects the multi-stage contact between gas and oil that occurs in the reservoir displacement processes. Thus this experimental study , demonstrates the indisputable interrelationship between interfacial tension and miscibility and hence encourages the wide use of VIT technique for rapid and cost-effective determination of minimum miscibility pressures and enrichments in improved oil recovery applications. Copyright 2006, Society of Petroleum Engineers

Comparison of Minimum Miscibility Pressures Determined from Gas-Oil Interfacial Tension Measurements with Equation of State Calculations

Miscible gas injection has been widely used as the most popular enhanced oil recovery process for light oil reservoirs. For technical and economic success of miscible gas injection projects, an accurate laboratory measurement of minimum miscibility pressure at reservoir temperature is essential. In addition to the existing laboratory techniques of measuring MMP namely slim-tube and rising bubble, recently a new technique of measurement called vanishing interfacial tension (VIT) has been developed. This new technique enables rapid and cost-effective determination of MMP. Hence, the objective of this study is to compare the minimum miscibility pressures determined from gas-oil interfacial tension measurements with those obtained from phase behavior calculations based on equations of state (EOS). For this purpose, two commercial crude oils namely Rainbow Keg River (RKR) and Terra Nova have been used, since the PVT data necessary for EOS calculations and the experimental values of MMP were available for these two reservoir cases. Peng-Robinson (PR) equation of state within a commercial software package has been used. The effects of tuning and non-tuning the equation of state on MMP calculations have been examined. For the two reservoir cases considered in our study, tuned PR-EOS yielded significant differences between MMPs from EOS calculations and VIT measurements, while untuned PR-EOS yielded reasonable match with experiments. In the case of RKR crude oil, the untuned EOS predictions were consistently higher by about 3.0-5.0 MPa than the experimental MMP from the VIT technique. For Terra Nova crude oil, in three out of five cases studied, the visible MMPs from the VIT experiments reasonably matched with untuned EOS calculations. Therefore, these comparisons of VIT results with EOS predictions clearly demonstrate that this new technique of vanishing interfacial tension is quite promising and reliable

Measurement of Surfactant-Induced Interfacial Interactions at Reservoir Conditions

The effect of surface-active chemicals on oil-water interfacial tension (IFT) and wettability in crude oil-brine-rock systems at reservoir conditions is important in enhanced oil recovery processes. However, most of the experimental studies on IFT and contact angles have been conducted at ambient conditions and using stocktank crude oils. In this study, live and stocktank crude oils have been used at reservoir conditions to make IFT and dynamic contact angle measurements using the Drop Shape Analysis (DSA) and Dual-Drop-Dual-Crystal (DDDC) techniques, respectively. Yates reservoir rock and fluids and two types of surfactants (nonionic and anionic) in varying concentrations have been used at reservoir conditions of 82° F and 700 psi. The dynamic oil-water IFT was found to be a strong function of oil composition, temperature and showed a slight dependence on pressure. An attempt has been made to explain the dynamic behavior of IFT using a four-stage mechanistic model involving induction, diffusion, kinetic barrier and equilibrium stages. The significant difference observed between the advancing contact angles of live oil (55°) and stocktank oil (154°) clearly indicates the need to use live oils at reservoir conditions to determine in-situ reservoir wettability. Anionic surfactant altered the weakly water-wet behavior of live oil to strongly oil-wet (165°). It was also able to alter the strong oil-wet behavior of stocktank oil to less oil-wet (\u3c135°). The nonionic surfactant was able to alter water-wet live oil system to intermediate-wet (82°), while it did not affect the strongly oil-wet behavior of stocktank oil system. The oil-wet behavior observed with the live oil due to the surfactants used indicates the possibility of these surfactants to develop continuous oil-wet paths for potential mixed wettability development. Thus, this study is of practical significance where the surfactant-induced wettability alterations to either intermediate-wet or mixed-wet can result in improved oil recovery through lowering of both capillary and adhesion forces. Copyright 2005, Society of Petroleum Engineers

Beneficial effects of wettability altering surfactants in oil-wet fractured reservoirs

In fractured reservoirs, an effective matrix-fracture mass transfer is required for oil recovery. Surfactants have long been considered for oil recovery enhancement, mainly in terms of their ability to reduce oil-water interfacial tension. These surfactants are effective when the fractured formations are water-wet, where capillary imbibition of surfactants from the fracture into the matrix contributes to oil recovery. However, another beneficial aspect of surfactants, namely their ability to alter wettability, remains to be explored and exploited. Surfactants capable of altering wettability can be especially beneficial in oil-wet fractured formations, where the surfactant in the fracture diffuses into the matrix and alters the wettability, enabling imbibition of even more surfactant into the matrix. This sequential process of initial diffusion followed by imbibition continues well into the matrix yielding significant enhancements in oil recovery. In order to test this hypothesis of sequential diffusion-imbibition phenomenon, Dual-Drop Dual-Crystal (DDDC) contact angle experiments have been conducted using fractured Yates dolomite reservoir fluids, two types of surfactants (nonionic and anionic) and dolomite rock substrates. A new experimental procedure was developed in which crude oil equilibrated with reservoir brine has been exposed to surfactant to simulate the matrix-fracture interactions in fractured reservoirs. This procedure enables the measurements of dynamic contact angles and oil-water interfacial tensions, in addition to providing the visual observations of the dynamic behavior of crude oil trapped in the rock matrix as it encounters the diffusing surfactant from the fractures. Both the measurements and visual observations indicate wettability alterations of the matrix surface from oil-wet to less oil-wet or intermediate wet by the surfactants. Thus this study is of practical importance to oil-wet fractured formations where surfactant-induced wettability alterations can result in significant oil recovery enhancements. In addition, this study has also identified the need to include contact angle term in the dimensionless Bond number formulations for better quantitative interpretation of rock-fluids interactions. © 2006 Elsevier B.V. All rights reserved